Condensate banking in natural gas reservoirs can hinder the productivity of production wells dramatically due to the multiphase flow behaviour around the wellbore. This phenomenon takes place when the reservoir pressure drops below the dew point pressure. In this work, we model this occurrence and investigate how the injection of CO 2 can enhance the well productivity using novel discretization and linearization schemes such as mimetic finite difference and operator-based linearization from an in-house built compositional reservoir simulator. The injection of CO 2 as an enhanced recovery technique is chosen to assess its value as a potential remedy to reduce carbon emissions associated with natural gas production. First, we model a base case with a single producer where we show the deposition of condensate banking around the well and the decline of pressure and production with time. In another case, we inject CO 2 into the reservoir as an enhanced gas recovery mechanism. In both cases, we use fully tensor permeability and unstructured tetrahedral grids using mimetic finite difference (MFD) method. The results of the simulation show that the gas and condensate production rates drop after a certain production plateau, specifically the drop in the condensate rate by up to 46%. The introduction of a CO 2 injector yields a positive impact on the productivity and pressure decline of the well, delaying the plateau by up to 1.5 years. It also improves the productivity index by above 35% on both the gas and condensate performance, thus reducing production rate loss on both gas and condensate by over 8% and the pressure, while in terms of pressure and drawdown, an improvement of 2.9 to 19.6% is observed per year.

Unconventional reservoirs such as shale and tight sandstones that with ultra-low permeability, are becoming increasingly significant in global energy structures ( Pejman T, et al., 2017 ). For these reservoirs, successful hydraulic fracturing is the key to extract the hydrocarbon resources efficiently and economically. However, the intrinsic mechanisms of fracturing growth in the tight formations are still unclear. In practice, fracturing design mainly depends on hypothetical models and previous experience, which leads to difficulties in evaluating the performance of the fracturing jobs. Therefore, an improved method to optimize parameters for fracturing is necessary and beneficial to the industry. In this paper, a data-driven approach is used to evaluate the factors that dominate the production rate from tight sandstone formation in Changqing Field which is the largest oil field in China. In the model, the input parameters are classified into two categories: controllable parameters (e.g. stage numbers, fracturing fluid volume) and uncontrollable parameters (e.g. formation properties), and the output parameter is the accumulated oil production of the wells. Data for more than 100 wells from different formations and zones in Changqing Field are collected for this study. First, a stepwise data mining method is used to identify the correlations between the target parameter and all the available input parameters. Then, a machine learning model is developed to predict the well productivity for a given set of input parameters accurately. The model is validated by using separate data-sets from the same field. An optimize algorithm is combined with the data-driven model to maximize the cumulative oil production for wells by tuning the controllable parameters, which provides the optimized fracturing design. By using the developed model, low productivity wells are identified and new fracturing designs are recommended to improve the well productivity. This paper is useful for understanding the effects of designed fracturing parameters on well productivity in Changqing Oilfield. Furthermore, it can be extended to other unconventional oil fields by training the model with according data sets. The method helps operators to select more effective parameters for fracturing design, and therefore reduce the operation costs for fracturing and improve the oil and gas production.

Water imbibition is a key factor affecting the flowback system of shale gas wells after volume fracturing. This paper took shale samples from the Longmaxi formation (LF) in the Sichuan Basin as subjects, the experiments of shale water imbibition under different influencing factors were carried out. The water imbibition law was analyzed, and the shale water imbibition capacity was quantitatively characterized, the question if shut-down is necessary after volume fracturing of wells in shale gas reservoir has been answered objectively. The experimental results show that: according to imbibition saturation, the shale water imbibition can be divided into 3 periods, imbibition diffusion, imbibition transition and imbibition balance periods. Among them, the imbibition diffusion period is the main period for imbibition capacity rise. The shale sample with horizontal bedding had much larger imbibition capacity than the sample with vertical bedding. The initial micro-fractures provide percolation pathways for shale imbibition, making flow resistance drop and imbibition capacity increase rapidly. Imbibition capacities of the shale samples to different types of fluids in descending order were: deionized water, slick water, 2% KCl solution and kerosene. The micro-fracfures induced by shale hydration were mainly lamellation, with obvious directionality. Shale hydration can improve the fracturing effect of reservoir, resulting in the increase of porosity of 0.08-1.04 times and increase of permeability of 2.3-173.6 times. The study results can provide scientific basis for the optimization of flowback system of shale gas wells.

Hydraulic fracturing is a widespread well stimulation treatment in the oil and gas industry. It is particularly prevalent in shale gas fields, where virtually all production can be attributed to the practice of fracturing. It is also used in the context of tight oil and gas reservoirs, for example in deep-water scenarios where the cost of drilling and completion is very high; well productivity, which is dictated by hydraulic fractures, is vital. The correct modeling in reservoir simulation can be critical in such settings because hydraulic fracturing can dramatically change the flow dynamics of a reservoir. What presents a challenge in flow simulation due to hydraulic fractures is that they introduce effects that operate on a different length and time scale than the usual dynamics of a reservoir. Capturing these effects and utilizing them to advantage can be critical for any operator in context of a field development plan for any unconventional or tight field. This paper focuses on a study that was undertaken to compare different methods of simulating hydraulic fractures to formulate a field development plan for a tight gas field. To maintaing the confidentiality of data and to showcase only the technical aspect of the workflow, we will refer to the asset as Field A in subsequent sections of this paper. Field A is a low permeability (0.01md-0.1md), tight (8% to 12% porosity) gas-condensate (API ~51deg and CGR~65 stb/mmscf) reservoir at ~3000m depth. Being structurally complex, it has a large number of erosional features and pinch-outs. The study involved comparing analytical fracture modeling, explicit modeling using local grid refinements, tartan gridding, pseudo-well connection approach and full-field unconventional fracture modeling. The result of the study was to use, for the first time for Field A, a system of generating pseudo well connections to simulate hydraulic fractures. The approach was found to be efficient both terms of replicating field data for a 10 year period while drastically reducing simulation runtime for the subsequent 10 year-period too. It helped the subsurface team to test multiple scenarios in a limited time-frame leading to improved project management.

Ascertaining the characteristics of fracture system at different scales integratedly is very important for performing efficient exploration and development activities of specific shale gas reservoirs. In this paper, an area around 250 square kilometers in Changning Block of Sichuan Basin is taken as an example, which belongs to Chinese Shale Gas Development Demonstration Plot. Seismic structural interpretation was performed detailedly based on original seismic amplitude cube and derived edge-detection cubes, and then the technologies of finite element horizon flattening, orthogonal decomposition principal component analysis, seismic discontinuity patch auto-extraction and paleo-stress field inversion were applied, together with the existing regional geological understanding and fracture information in wells, to figure out the staging and grouping of fracture system at seismic scale (i.e., at large and middle scales), at the same time to clarify the regional tectonic evolution and its genetic relationship with fractures at different scales such as the ones revealed by seismic data and cores or image logs. The following conclusions were reached. (a) The tectonic movements affecting the development of fracture system in study interval mainly happened during Yanshanian-Himalayan periods, i.e., 3 compressional tectonic episodes which were nearly in S-N direction in Late Yanshanian period, in NNE-SSW direction in Early Himalayan period, and in NWW-SEE direction in Middle Himalayan period respectively. (b) The Late Yanshanian tectonic event primarily formed long-axis anticlines and synclines, thrust faults and fault-related fractures, all of which were nearly in E-W trending, and fold-related fractures in different directions. (c) The Early Himalayan tectonic event mainly formed genetically related conjugate fracture sets including strike-slip faults and shear fractures both in NNW and NE directions, and transverse extensional fractures. (d) The Middle Himalayan tectonic event chiefly formed thrust faults, and related fractures and folds in NNE~NE direction, and transverse extensional fractures. (e) Furtherly our work demonstrated that such kind of fracture system analysis was of great significance in building discrete fracture network, providing precautionary advice for drilling engineering, and optimizing completion program and field development plan, etc. Hence, integrated fracture system analysis at full scales to reach more meaningful and robust conclusions is essential work for unconventional resources evaluation and characterization.

Hydraulic fracturing technology provides a guarantee for effective production increase and economic exploitation of shale gas wells reservoirs. Propped fractures formed in the formation after fracturing are the key channels for shale gas production. Accurate evaluation of local propped fracture conductivity is of great significance to the effective development of shale gas. Due to the complex lithology and well-developed bedding of shale, the fracture surface morphology after fracturing is rougher than that of sandstone. This roughness will affect the placement of the proppant in the fracture and thus affect the conductivity. At present, fracture conductivity tests in laboratories are generally based on the standard/modified API/ISO method, ignoring the influence of fracture surface roughness. The inability to obtain the rock samples with the same rough morphology to carry out conductivity testing has always been a predicament in the experimental study on propped fracture conductivity. Herein, we propose a new method to reproduce the original fracture surface, and conductivity test samples with uniform surface morphology, consistent mechanical properties were produced. Then, we have carried out experimental research on shale-propped fracture conductivity. The results show that the fracture surfaces produced by the new method are basically the same as the original fracture surfaces, which fully meet the requirements of the conductivity test. The propped fracture conductivity is affected by proppant properties and fracture surface, especially at low proppant concentration. And increasing proppant concentration will help increase the predictability of conductivity. Due to the influence of the roughness of the fracture surface, there may be an optimal proppant concentration under a certain closure pressure.

Geomechanical rock properties correlations and modeling approach for conventional reservoirs are inappropriate and unsuitable for unconventional shale gas reservoirs where the shale formation is strong and has very low porosity. These correlations are critical in the development of 1D and 3D geomechanical models which are used for various field applications including drilling optimization, hydraulic fracturing design and operation, and field management. The study investigates various geomechanical rock properties and their relationships to one another using data extracted from rock mechanics testing conducted on shale core samples. For rock elastic properties correlations, dynamic elastic properties determined from compressional sonic velocity, shear sonic velocity and density are plotted against laboratory-measured static elastic properties obtained from triaxial tests. Steps were taken to further refine the properties correlations by separating the data from vertical and horizontal core samples, using data from tests conducted at in-situ confining stress condition, and focusing on data only taken from Field A and nearby fields. Similar steps were also taken to develop the correlations for rock strength properties. Correlations for the shale anisotropic elastic properties were also developed based on ratio of horizontal and vertical elastic properties. Blind tests were conducted on three wells in Field A using the new rock properties correlations which showed good matching of the predicted geomechanical properties with the new correlations and core measured test data.

Given the importance of the O&G sector (exports, national budget, royalties, etc.) in the economy of countries that possess this natural resources and the increased exposure of the economy of these to the cyclical dynamics of the O&G industry, it becomes necessary unequivocally an analysis and comparison of the most used market concentration measures applicable to the upstream framework that affect the distribution of oil production and reserves to determine proposals for an increase in competitiveness, in this case analyzing the metrics in the range 2004-2016 in Colombia. The process starts from collecting the most reliable information from different associations, regulators and sources, calculating the most used market concentration measures, considering assumptions for the statistical analysis of the data as tests of normality (Shapiro-WilK Test) and then analysis and comparison of the HHI as measure of concentration of the E&P upstream market in Colombia obtained conclusions and recommendations. Ideal values were determined and recommended according to better HHI references that would imply a less concentrated upstream sector and competitive advantage to the country regionally to attract foreign direct investment (FDI). An alienation and division of National oil company- NOC from the Colombian state is proposed, divide upstream into 3 E&P companies plus 1 Midstream Transporting Company + 1 Downstream Refining Company, it is recommended given the opportunity of a possible development of unconventional resources in the country, and the economic uncertainty at the beginning of these developments, that the opportunities for pilots and initial projects be by law and in principle distributed among various private E&P operators or in associations of the state company with experienced operators, this would distribute the exploratory risk of the projects, improve the sector's competitiveness and avoid unnecessary investment exposure to the state in these ventures. The objectives, methods, processes and results obtained can be homologated to other countries with NOC, showing a direct roadmap to follow so that the economic associated with natural hydrocarbon resources allow us to further leverage the development of societies in general, but mainly developing countries rich in these resources in an environment of low prices and increasing competitiveness.

Tight gas reservoirs are widely distributed in China, which occupies one-third of the total resources of natural gas. The typical development method is under primary depletion. However, the recovery of tight gas is only around 20%. It is necessary to explore a new technique to improve tight gas recovery. Injecting CO 2 into tight gas reservoirs is a novel trial to enhance gas recovery. The objective of this work is to verify and evaluate the effect supercritical CO 2 on enhancing gas recovery and analyze the feasibility of CO 2 enhance gas recovery of tight gas reservoir. Taken DND tight sandstone gas reservoir in North China as an example, 34 wells of DK13 wellblock were chosen as CO 2 Enhanced gas recovery pilot area with 10-year production history. Six injection scenarios were studied. Numerical simulation indicated that the recovery of the gas reservoir of DK13 well area was improved by 8-9.5 percent when CO 2 content of producers reaches 10 percent. The annual CO 2 Storage would be 62 million cubic meters (110 thousand tons) and the total CO 2 storage would be around 800million cubic meters (1.5 million tons). After the environmental parameter evaluation of injectors and producers, the anticorrosion schemes were put forward and the feasibility evaluation and schemes of facilities were presented. The analysis results indicated that DK13 wellblock was suitable for CO 2 enhanced gas recovery no matter geologic condition, injection & production technology and facilities. However, under the current economic conditions, DK13 wellblock was not suitable for CO 2 to enhance gas recovery. However, if gas price rise or low carbon strategy implement, the pilot test could be carried out. In brief, CO 2 could be an attractive option to successfully displace natural gas and decrease CO 2 emissions, which is a promising technology for reducing greenhouse gas emission and increasing the ultimate gas recovery of tight gas reservoirs. This economic analysis, along with reservoir simulation and laboratory studies that suggest the technical feasibility of CSEGR, demonstrates that CSEGR can be feasible and that a field pilot study of the process should be undertaken to test the concept further.

Adsorption isotherms of methane and carbon dioxide adsorption isotherms on shale samples are measured and the simplified local density (SLD) model is used to match the experimental data. The SLD equation also has the generic modeling capabilities to draw the deviation from bulk properties as a function of fluid-solid interaction energies. Still, compared to other available techniques such as molecular simulation, SLD has an advantage of mathematical simplicity and being run at shorter time interval. The model also has satisfactory potential to paint the underlying mechanisms for adsorption preference of one fluid component over the other. The higher adsorption preference of carbon dioxide is reflected in the measurement data and the adsorption model is successfully used to fit the data. In addition to different critical properties of carbon dioxide compared to methane, the main important factor that may describe the high adsorption affinity of carbon dioxide is the fluid-solid potential energy. As shown in this work, the potential energy function shows deeper well depth, the deeper the well depth, the stronger the interaction between the fluid particles and solid surface. By storing gas in high density, liquid like adsorbed phase, the adsorption mechanism can enhance the overall storage capacity of CO 2 in deep reservoir rock relative to if there were a free phase alone.

Quantitative identification of diagenetic facies is critical for favorable reservoir prediction. In this study, the diagenetic facies of the Chang-8 reservoir in the Zhenbei area of the Ordos Basin was investigated using an integrated analysis of casting thin sections, scanning electron microscopy (SEM) and X-ray diffraction (XRD). The Chang-8 reservoirs can be subdivided into five major diagenetic facies categories: 1) weakly-dissolved chlorite cemented facies, 2) moderately-compacted mineral dissolution-susceptive facies, 3) moderately-dissolved kaolinite-bearing facies, 4) moderately-compacted carbonate cemented facies, and 5) strongly-compacted tight sandstone facies. On the basis of the above analyses, the diagenetic facies were identified from well logs by involving the supervised-mode self-organizing-map neural network (SSOM) algorithm. Six wireline logs sensitive to the diagenetic facies characteristics were used as the model input, the diagenetic facies prediction model was built using SSOM. The prediction results of the diagenetic facies are in good agreement with the core analysis types, with a matching of 83.87%. Our work also sheds light on reservoir typing by linking the diagenetic facies with reservoir quality and oil testing data.

An intrashelf depo-center hosts the Jurassic carbonate source rock, which contains one of the richest hydrocarbon producing source rock intervals in the world. The understanding of kerogen distribution and maturity across this frontier unconventional basin is key for focused prospectivity and future development. A correlation between total organic carbon (TOC) and porosity and key reservoir parameters has been observed. The porosity, measured using the Gas Research Institute (GRI) methodology, shows a poor TOC values correlation, as measured by LECO. A substantial amount of liquid hydrocarbon has been recorded during pyrolysis in the S1 peak, constituting a significant portion of the measured TOC. This effect has to be quantified in order to avoid issues when calibrating logs to predict TOC, saturation and porosity. An analytical workflow was developed to remove the free hydrocarbon and bitumen from samples. Each sample was split into two parts; and sent for LECO-TOC and SRA pyrolysis. The initial run was conducted using an industry standard sample preparation method. In the second run, sample preparation included a solvent extraction. An organic solvent was used to remove the free hydrocarbons and mobile bitumen, thus taking off the S1 and oil shouldering effects on the S2 emission peak on the pyrograms. The two resulting data sets were then compared, and showed a net reduction of TOC in addition to increasing in Tmax values for most of the post-extraction samples. Results of this detailed analysis yielded a new set of thermal maturity values. Furthermore, log-derived TOC calculations have been recalibrated resulting in a more accurate petrophysical model. These corrections generated more reliable results that greatly enhanced our understanding of basin maturity variations and organic matter distribution; thus decreasing uncertainty and refining in-place resource estimations across the basin.

Source rocks, such as, organic-rich shale formations have multi-scale pore structure with nano-scale features contributing to hydrocarbons storage. These hydrocarbons are divided across the organic nanopore size distribution of the source rock into fluids with altered properties. This alteration in organic nanopores is a due to multi-component hydrocarbon fluid with a significant compositional change. The smaller the pores are, the heavier the hydrocarbons in the pores become bottom. During production, nanopores release mainly the lighter end of the mixture. Hence, the composition inside the pores becomes even heavier, top. The viscosity and apparent molecular weight of the hydrocarbon mixture left behind increase significantly during the depletion . Capillary condensation of the fluid could develop in the smaller end of the nanopores depending on the thermodynamic conditions, i.e., composition, pressure and temperature. When develops, the capillary condensation resists and, hence the vaporization is avoided, even when the depletion pressure is reduced down to the pressure of vaporization, i.e., bubble point pressure. The average mean-free path length of the mixture molecules is also influenced by the nanopores in an unpredictive way . The path length values stay steady and may even decrease in small nanopores due to the capillary condensed phase occurence. The so-called nano-confinement effects significantly limit the release of hydrocarbons from the source rock organic matter, in particularly from those pores with sizes smaller than 10nm. GCMC simulations showing fluid composition variation of hydrocarbons in nano-scale pores at various reservoir pressure. Composition data is normalized using the fluid composition outside of the nanopore. TOP: Composition variation in 4nm pore with changing reservoir pressure. BOTTOM: Composition variation in various pores at 2,000psi reservoir pressure. Viscosity of the fluids in nanopores. The viscosity is computed using non-equilibrium periodic-shear-flow method. The computed viscosity values are normalized using the bulk fluid viscosity at the same pressure and temperature. The results show significant increase in viscosity in pores with sizes less than 5nm. Knudsen number estimated using the trajectories of the hydrocarbon molecules in nanopores from molecular simulations. Left: Kn with varying pressure in 4.4 nm pore. Right: Kn with varying pores size at 2,000 psi. The heavier fluid composition in the organic nanopores leads to stunning new results for the mixtures Knudsen numbers (Kn) . Based on the kinetic theory calculation with pure methane, we would have anticipated that the flow regime should change from slip to transition occurs in nano-pores and at low-pressure condition. In contrast, Kn for the confined fluids remains unchanged in the same conditions. Because the mixture in nano-pores and at low pressure is heavier and this leads to a significant reduction in the mean free path length. The pressure effect, on the right, due to the depressurization is compensated by the changes in the composition. The pressure increases the inter-molecular spacing among the molecules and, hence, lowers the chance for a collision, but the compositional changes increase the chance for collision. Thus the, compositional variation in the nanopore during depressurization compensates for this pressure effect. Eventually, the effective mean free path of the hydrocarbon fluids shows a somewhat constant value for the fluid mixtures innanopores. The results also indicate that we can describe the transport of fluids in the source rocks using continuum mechanics theory. Based on these microscopic-level discussions, the concept of composition redistribution of the produced fluids into naopores is introduced by Akkutlu et al. (2017). This concept is crucial for the organic-rich source rock resource assessment. The hydrocarbon in-place calculations, the reserve calculations, the cut-off value for the effective porosity associated with trapped and mobile fluids, the fluid flow regimes considerations, reservoir flow simulation studies are all influenced by the redistributed composition in the nanopore size distribution. Otherwise, there will be added uncertainties in the reserve estimation. shows the composition redistribution of the produced fluids. The reservoir engineering studies require that the composition of the fluids gathered together from the separator must be recombined to the so-called well stream fluid composition for the subsequent reservoir analyses. The recombination calculations can be performed using correlations developed for two-stage and three-stage separators. . Recombination calculations are carried out by estimating the recombined composition or specific gravity of the flowing well stream fluid from either the composition ( yi, xi ) or the specific gravity values ( Γ g , Γ o ) of the produced gas and liquid. The recombined data is then used for the prediction of the fluid properties, the equation of state and the liquid-vapor equilibrium in the formation under the subsurface conditions using laboratory PVT measurements or empirical correlations. Note, however, that the recombined fluid data must be re-distributed back into the formation in the case of source rocks holding organic nanopores. The redistribution calculations are proposed in using grand canonical Monte Carlo molecular simulations, where the the composition in nanopore is predicted based on the fluid pressure and composition outside of the nanopores in large volume regions in the reservoir, such as micro-fractures and cracks. Their approach has led to modifications in the volumetric method of estimating hydrocarbon in-place, and the method of reservoir flow simulations for the prediction of the reserves for the source rocks. Composition re-distribution of the produced fluids in the organic-rich source rock.

The main objective of this research is to present two new approaches for unconventional gas reservoirs rock typing methods. In our rock typing we automatically adjust rock type classes by optimization routines using specific surface area per unit grain volume and volume of kerogen values. Further, our results are compared to other conventional rock typing methods. The presented methos can enhance unconventional reservoir characterization by developing and/or establishing new correlations. This is exemplified through a real case study of an unconventional shale gas reservoir called Upper Safa formation that is located in the western desert of Egypt. Addition we describe the fluid properties more consistently through a full integration of unconventional rock parameters such as surface roughness factor, gas adsorption, type of kerogen, volume of kerogen, level of maturity and total organic carbon content. The Upper Safa formation is a shale gas unconventional resource play. Interpretation analysis has confirmed the hydrocarbon potential in the Upper Safa formation. Geochemical pyrolysis analysis has been used to confirm the presents of Kerogen type III. Total organic carbon content results are obtained within the ranges of very good petroleum potential according to Rock Eval pyrolysis from 2% to 4% TOC. The Upper Safa formation is a highly heterogeneous formation, with the Dykstra Parson permeability variation giving a heterogeneity value close to 100%. Large variation in the permeability, rangeing from milli-Darcy to nano-Darcy, is common for unconventional shale reservoirs. This large variation in permeability complicates rock typing of the reservoar. Several conventional rock typing methods have been applied to for the zonation problem, including as Amaefule, Discrete rock typing, Flow Zone Indicator, permeability predictive model, Winland, and a modified Winland. For comparison of the different methods, they have all been forced to produce the same number of rock classes. We have established routines for optimal selection of the boundary values distinguishing these rock classes. We also present two new rock typing techniques utilizing specific surface area per unit grain volume and TOC values.

Unconventional petroleum resources have become the key to the exploration and development of the world’s petroleum industry. The unconventional exploration and development of reservoirs, however, still remain low due to technological and economic constraints. Considering the extremely low permeability of unconventional petroleum resources, efficient economic exploitation cannot be realized without hydraulic fracturing technology. Therefore, the fracturing technology which has both quality and economic efficiency, is the key to production and yield increase of unconventional petroleum reservoirs. In this study, a self-propping hydraulic technology was creatively proposed to solve the disadvantages of existing hydraulic fracturing technologies, especially unconventional fracturing technologies. Moreover, technical theories, performance and modes of the proposed liquid self-propping fracturing technology were introduced. This technology not only solves the technical pain points of conventional sand fracturing, as the successful research of this technology also provides a new design concept and technological change for hydraulic fracturing technology.

Relatively, the gas production is low for fractured horizontal wells in normal pressure shale gas plays with a quick production decrease, resulting in larger difficulty for commercial breakthrough and economic development. Accordingly fracturing technology is under study urgently. On condition that production increased and engineering cost decreased, together with feasible and practical fracturing technology, the production potential is studied to put forward several hydraulic fracturing treatment. Firstly, cluster spacing is decreased, while increasing cluster number per stage, thus, there are more total clusters for one well with less stages, the influence of induced stress could be strengthened especially using plane perforation. Secondly, using high viscosity gel as pre fluid or flushing fluid among injecting period, to extend fracture through layers vertically. Thirdly, by use of ultra-low density small mesh proppant, increasing net pressure sharply by plugging the front of fracture. Fourthly, increasing ratio of lower viscosity slick water, small mesh proppant and higher viscosity gel, to improve hydraulic fracturing pumping pattern and technological parameter by varying viscosity, varying displacement, varying mesh proppant, so multiscale fracture propagate and propped with corresponding size of proppant. Fifthly, deminishing lower effective and non-effective clusters through studying geological and engineering sweetness. Aiming at production increased and engineering cost decreased, the production potential is studied to put forward several hydraulic fracturing treatment, which is feasible and practical. Good result was observed in pilot application of D well and L well, providing theoretical support for developing effectively and economically in similar shale gas play.

In shale reservoirs, the gas productivity is severely reduced due to the formation tightness. The extreme low permeability of shale formations can result in reducing the gas flow into the borehole, and consequently the gas production can be significantly reduced. This paper presents an effective technique for enhancing the gas productivity for shale gas reservoirs using thermochemical fluids. The used chemicals can generate heat and pressure in-situ and improve the flow condition by creating micro- factures in the shale rocks. Experimental measurements and analytical calculations were carried out to investigate the enhancement in gas productivity for shale samples due to the injection of thermochemical fluids. Coreflooding experiments and rate transient analysis (RTA) were conducted as well as nuclear magnetic resonance (NMR) measurements. Tight core samples from eagle ford formation were used in the flooding experiments. The improvement in gas productivity due to thermochemical injection was evaluated using rate transient analysis. The profiles of pressure-drop and gas flow-rate were used to estimate the gas productivity before and after the chemical treatment. NMR measurements were used to study the changes in the pore network due to thermochemical stimulation. The T2 signal distribution was obtained before and after the chemical injection. Furthermore, analytical calculations were performed to estimate the enhancement in gas productivity due to the thermochemical treatment. The increase in absolute open flow (AOF) and the productivity index (PI) due to the chemical treatment were determined. Results showed that treating shale rocks with thermochemical fluids can enhance the gas productivity by 62% and reduce the capillary pressure by more than 45%. Also, the absolute open flow can be increased four times due to the thermochemical injection into shale reservoirs. The generated heat and pressure due to thermochemical treatment can induce permanent alterations in the shale matrix and then improve the hydrocarbon flow for long term. NMR measurements, before and after the treatment, confirm the creation of tiny fractures during the chemical injection. The novelty of this work is that an effective treatment is presented to enhance the gas productivity for shale formations. Ultimately, this study will be very useful for treating the shale reservoirs with thermochemical fluids to improve the gas productivity, and consequently enhance the total gas production from shale reservoirs.

Molecular diamonds, known as diamondoids are naturally occurring hydrocarbon compounds found in crude-oil and rock extracts. Diamondoids feature unique thermal stability owing to the carbon cage-like backbone structures. Therefore, unlike classical geochemical compounds, diamondoids provide a robust molecular-marker for fingerprinting hydrocarbon fluids and assessing thermal maturity. In this study, we present the application of quantitative extended diamondoid analysis (QEDA), together with compound-specific isotope analysis of diamondoid hydrocarbons (CSIA-D) recovered from the major USA unconventional reservoirs. The application of diamondoids is demonstrated for three major unconventional reservoirs of North America. A collection of crude oils, condensates, and rock-extracts were examined from Shale formations including the Eagle Ford and Woodford Shales. Core and fluid samples are located within three major US basins including Maverick, Permian and Anadarko basins. Hydrocarbons were analyzed using gas chromatography-mass spectrometry analytical method for measuring the absolute concentrations of diamondoid and biomarker compounds. Further, diamondoid-isolates were analyzed using isotope ratio mass spectrometry equipped with gas chromatography for CSIA-D. Diamondoids composition provides a unique geochemical tool for the unconventional reservoir, in detecting petroleum mixing and fingerprinting fluids of various maturities. In the Anadarko Basin, the Woodford Shale produced oils in central Oklahoma show a dual signature of elevated diamondoid abundance together with the biomarkers, suggesting hydrocarbon mixing of black-oils and cracked dry and wet gas. Moreover, Eagle Ford fluids produced from the Maverick Basin are mature hydrocarbons lacking biomarkers to allocate their zone of production. Diamondoid fingerprints allowed for tracking their production through time and identifying the sweet-spot depth in which most hydrocarbons were contributing. In the Permian Basin, diamondoid fingerprints were used to establish unmixed end-members from oils produced from the Woodford Shale, Eilenberg Carbonate and Pennsylvanian shale, and identify highly mature mixed oil commingled between the Woodford Shale and Ellenburger carbonate source rocks. Identification of the sweet-spots and allocating produced hydrocarbons are crucial factors in the successes of unconventional plays. Most produced fluids in major US unconventional reservoirs are at high levels of thermal maturity, at which classical biomarkers are either absent or in very low concentrations; whereas, diamondoids are abundant, providing a novel technique to fingerprint fluids throughout the range of different maturity stages. In unconventional reservoir operation, diamondoids can be used in time-lapse geochemistry as a cost-effective tool along with other seismic-based techniques.

Unconventional gas developments in the Middle East are relatively new, compared to the established shale developments in the US. The Middle East developments are generally owned or controlled by a single entity, e.g. the national oil company, rather than the model often seen in the US of multiple operators focused on their particular ‘block’. This can lead to a different approach to the full field development (FFD), with more emphasis needed on de-risking projects, particularly during their early stages. This de-risking process is essential to limit the exposure of the single owner to the inherent uncertainties of an unconventional development as the scale of the project increases. This paper considers multiple areas of uncertainty and risk associated with an unconventional gas field development. From the necessity for clear project drivers and team alignment, through to the uncertainties of well production and water management, risks are identified with recommendations to help projects avoid pitfalls and manage the inherent risks of developing a large unconventional field in the Middle East. The paper concludes that a Middle Eastern project can't, in all cases, simply adopt the practices used in the US. The project may choose to take guidance from the US but since the operating environment is different, the risks, and therefore management of risks, will in many cases need to be addressed differently.

Current global energy demand and supply gap needs the best engineering methods to recover hydrocarbons from the unconventional hydrocarbon formations. Unconventional hydrocarbons normally present in deep formations, where the overburden stresses and formation integrity are very high. When fracturing these types of formations, the hydraulic fracturing job becomes much more challenging, and in some scenarios, pumping reached to the maximum capacity limits without generating any fracture. This reduces the operational gap to optimally placed hydraulic fractures. In the present research study, a novel thermochemical fracturing approach is presented to reduce the breakdown pressure of the high-strength formations. The hydraulic fracturing experiments presented in this study are carried out on ultra-tight cement block samples. The composition of cement blocks is synthesized in this way that it simulates the real rocks. The results showed that the newly proposed thermochemical fracturing approach reduced the breakdown pressure in ultra-tight cement from 1095 psia (reference breakdown pressure recorded from conventional hydraulic fracturing technique) to 705 psia. The post treatment experimental analysis showed that the thermochemical fracturing approach resulted in a deep and long fracture while conventional hydraulic fracturing resulted in a thin fracture. In addition to that, a Finite element analysis using ABAQUS is also presented. The main purpose of the numerical investigation is to confirm the sufficiency of the experimental data for reproducing the same breakdown pressure that included depiction of injection pressure versus time plots, failure loads and cracking patterns.